There are many types of steam generator systems that are employed for the generation of steam for use in the generation of electricity and chemical processing plants. Some of the steam generation systems combust fossil fuel such as coal, natural gas and oil in a steam generator vessel. An air supply to the steam generator vessel is required to provide oxygen for the combustion of the fuel. The combustion of the fuel results in high temperature combustion byproducts in a flue gas stream discharged from the steam generator vessel. To improve the thermal efficiency of the steam generator system the air supply to the steam generator vessel is heated by recovering heat from the flue gas stream in an Air Preheater (APH), such as a rotary APH.
Efficiency of the APH can be increased by using higher efficiency heat transfer elements and heat transfer elements with a greater heat transfer area. However, those skilled in the relevant art have not been able to realize the full potential of increased APH efficiency available through the use of higher efficiency heat transfer elements and greater heat transfer area of the heat transfer elements, because of operation limitations relating to the control of pollutants, as described herein.
The byproducts in the flue gas stream can include particulate matter and pollutants. For example, the combustion of coal results in combustion byproducts such as particulate matter in the form of fly ash and pollutants such as nitrogen oxides (NOX), sulfur dioxide SO2 and sulfur trioxide SO3 (collectively often referred to as SOx). The SO2 is formed as a result of the combustion of sulfur containing fuels such as high sulfur coal. The SO3 is formed by oxidation of the SO2 for example when oxygen content in the flue gas is too high or when the flue gas temperature is too high (e.g., greater than 800° C.). The SO3 can form a liquid aerosol known as sulfuric acid (H2SO4) mist that is very difficult to remove.
Environmental laws and regulations limit the amount of discharge of particulate matter and pollutants into the environment. Thus, various treatment systems have been employed to control the discharge of particulate matter and pollutants. For example, Selective Catalytic Reduction (SCR) is a treatment means for converting nitrogen oxides, also referred to as NOX, with the aid of a catalyst into diatomic nitrogen (N2) and water (H2O). Particulate control systems such as bag houses, wet Electro Static Precipitators (ESPs) and dry ESPs can be employed to remove particulate matter from the flue gas stream. Dry ESPs are more efficient and easier to maintain than wet ESPs, but dry ESPs require a drier flue gas stream than wet ESPs. Creating a dry flue gas stream can be difficult because as the flue gas temperature decreases below the dew point of SO3 at a cold-end of the APH, condensation can occur, thereby causing SO3 to form H2SO4 and a relatively wet flue gas. Moreover, if the flue gas contains the H2SO4 mist, then the less efficient wet ESP is typically employed to remove the H2SO4. In addition, the ESPs tend to experience dust fouling (e.g., an undesirable accumulation of fly ash on ESP collector plates and removal troughs) when the temperature of the flue gas is high (e.g., 130° C. or greater).
Another system employed for the control of particulate matter and pollutants is a Flue Gas Desulfurization (FGD) system. The FGD systems are primarily directed to removing any SO2, for example, by the use of SO2 absorbers. Wet SO2 absorbers typically spray water mixed with a sorbent on a stream of flue gas flowing through the SO2 absorber to absorb the SO2 from the flue gas. The flue gas exiting the SO2 absorber is saturated with water that contains some SO2. One operational limitation of the FGD systems is the flue gas exiting the SO2 absorber can be highly corrosive to any downstream equipment such as fans, ducts, and stacks. Another operational limitation of the FGD systems is that the SO2 absorbers require a substantial water supply and sorbent regeneration equipment.
One operational limitation relating to APH's is that employing heat transfer elements with increased heat transfer efficiency and area can cause the flue gas temperature to decrease below the dew point of SO3 at which temperature, condensation at a cold-end of the APH can occur. The SO3 reacts with the water to form sulfuric acid H2SO4 which condenses on the APH heat transfer elements. The particulate matter can adhere to the condensed H2SO4 causing fouling of the APH. Based on this operational limitation, those skilled in the relevant art have been discouraged from reducing the component temperature and/or flue gas temperature exiting the APH to below the dew point of SO3 and from further employing APH's with increased efficiency heat transfer elements and heat transfer area. This inability to completely realize the full potential of increasing the efficiency of the APH therefore limits the ability to increase the thermal efficiency of the steam generator system to be increased to its full potential.
As shown in FIG. 1 a prior art steam generator system is generally designated by the numeral 100. The steam generator system 100 includes a steam generator vessel 101 that includes a flue gas outlet 101B that is in communication with a Selective Catalytic Reduction (SCR) system 102 via an SCR inlet 102A. The SCR system 102 includes an SCR outlet 102B that is in communication with an air preheater (APH) 103 via a first APH inlet 103A. An air supply line 103D is in communication with a second APH inlet 103C. The APH 103 includes a first APH outlet 103E that is in communication with an inlet 101A to the steam generator vessel 101. The APH 103 includes a second APH outlet 103B that is in communication with an inlet 104A of an Electro Static Precipitator (ESP) 104. The ESP 104 includes an outlet 104B that is in communication with an inlet 105A of a fan 105 (e.g., an induced draft fan). The fan 105 includes an outlet 105B that is in communication with a hot side inlet 106XA of a heat recovery section 106X of a gas-to-gas heat exchanger (GGH). The heat recovery section 106X has a first outlet 106XB that is in communication with an inlet 107A of a Flue Gas Desulfurization (FGD) system 107. The FGD system 107 includes an outlet 107B that is in communication with a cold side inlet 106YA of a re-heating section 106Y of the GGH. The re-heating section 106Y includes a second outlet 106YB that is in communication with a fan inlet 108A of a fan 108. The heat recovery section 106X includes an inlet 106XC that is in communication with an outlet 106YD of the re-heating section 106Y via a sealed conduit 106Q for conveying a heat transfer medium therein. The heat recovery section 106X includes an outlet 106XD that is in communication with an inlet 106YC of the re-heating section 106Y via sealed conduit 106R for conveying the heat transfer medium therein. The fan 108 includes an outlet 108B that is in communication with an inlet 109A of an exhaust stack 109. The exhaust stack 109 includes a stack outlet 109B.
Operation of the steam generator system 100 involves supplying a fuel such as pulverized coal to the steam generator vessel 101. Air for combustion of the coal is provided via the air supply 103D which is heated in the APH 103 via a stream of hot flue gas that is discharged from the steam generator vessel 101 after having been treated for NOX reduction in the SCR 102. Flue gas that is discharged from the APH outlet 103B and supplied to the ESP 104 typically has a temperature of about 130° C. Operation of the ESP 104 at 130° C. tends to cause dust fouling in the ESP 104, as described herein. In order to increase the efficiency of SO2 removal in the FGD system 107, the temperature of the flue gas is reduced to about 90° C. in the GGH 106. However, because of pressure losses through the GGH 106 the fan 105 is required to increase the pressure of the flue gas to ensure continued flow at sufficient velocity through the GGH 106 and the FGD system 107. The desulfurization processing in the FGD system 107 reduces the temperature of the flue gas to about 50° C. as a result of contact the water in the FGD system 107. Discharge of flue gas into the stack 109 at such low temperatures tends to cause corrosion problems and a visible plume at the discharge 109B of the stack 109. To mitigate these problems, the flue gas is recirculated back into the GGH 106 to reheat the flue gas to about 90° C. Recirculation of the flue gas back through the GGH 106 results in further pressure losses and the fan 108 is required to increase pressure and velocity of the flue gas to an acceptable magnitude.
Drawbacks of the steam generator system 100 include: 1) the reduction in overall thermal efficiency due to the power consumed by the fans 105 and 108; 2) the dust fouling problems in the ESP 104 due to the high temperature of the flue gas; 3) the less than optimum APH 103 which cannot employ heating elements having a greater efficiency and area; 4) the inability to employ a dry ESP because of the presence of sulfuric acid H2SO4 in the flue gas; and 5) inefficiencies of the FGD 107 due to the high SO3 concentration of greater than 5 ppm in the flue gas.
As shown in FIG. 2, another prior art steam generator system 101′ is similar, in some regards, to the prior art steam generator system 100 of FIG. 1. Thus, similar components are designated with similar reference characters followed by a prime designation.
As shown in FIG. 2 the prior art steam generator system 100′ includes a steam generator vessel 101′ that includes a flue gas outlet 101B′ that is in communication with a Selective Catalytic Reduction (SCR) system 102′ via an SCR inlet 102A′. The SCR system 102′ includes an SCR outlet 102B′ that is in communication with an air preheater (APH) 103′ via a first APH inlet 103A′. An air supply line 103D′ is in communication with a second APH inlet 103C′. The APH 103′ includes a first APH outlet 103E′ that is in communication with an inlet 101A′ to the steam generator vessel 101′. The APH includes a second APH outlet 103B′ that is in communication with a hot side inlet 106XA′ of a heat recovery section 106X′ of a gas-to-gas heat exchanger GGH. The heat recovery section 106X′ has a first outlet 106XB′ that is in communication with an inlet 104A′ of an Electro Static Precipitator (ESP) 104′. The ESP 104′ includes an outlet 104B′ that is in communication with an inlet 105A′ of a fan 105′ (e.g., an induced draft fan). The fan 105′ includes an outlet 105B′ that is in communication with an inlet 107A′ of a Flue Gas Desulfurization (FGD) system 107′. The FGD system 107′ includes an outlet 107B′ that is in communication with a cold side inlet 106YA′ of a re-heating section 106Y′ of the GGH. The re-heating section 106Y′ includes an outlet 106YB′ that is in communication with a fan inlet 108A′ of a fan 108′. The heat recovery section 106X′ includes an inlet 106XC′ that is in communication with an outlet 106YD′ of the re-heating section 106Y′ via a sealed conduit 106Q′ for conveying a heat transfer medium therein. The heat recovery section 106X′ includes an outlet 106XD′ that is in communication with an inlet 106YC′ of the re-heating section 106Y′ via sealed conduit 106R′ for conveying the heat transfer medium therein. The fan 108′ includes an outlet 108B′ that is in communication with an inlet 109A′ of an exhaust stack 109′. The exhaust stack 109′ includes a stack outlet 109B′.
The steam generator system 101′ differs from the steam generator system 101 in that the GGH 106 is positioned between the APH 103′ and the ESP 104 in an effort to raise the temperature of the flue gas to 90° C. before entering the ESP 104′. While the steam generator system 101′ attempts to improve the operation of the ESP 104′, the other drawbacks of the steam generator system 101 remain.
Based on the foregoing there is a need for a steam generator system with improved thermal efficiency and particulate matter and pollution treatment systems.